Domestic drilling fleet was fully utilized during the third quarter, and generated an average margin per day of $10,237, up 7% from the prior quarter.

In Colombia, we expect to execute a contract with a new, multi-national client to begin operations later in the fourth quarter.

Steady improvement in well servicing activity as the outlook for completion-related services in our operating areas continues to strengthen.

Consolidated Financial Results

Revenues for the third quarter of 2018 were $149.3 million, down 4% from revenues of $154.8 million in the second quarter of 2018 ("the prior quarter") and up 27% from revenues of $117.3 million in the third quarter of 2017 ("the year-earlier quarter"). The decrease from the prior quarter is primarily attributable to weaker activity levels in wireline, which was partially offset by increased revenues in all other segments.

Net loss for the third quarter of 2018 was $5.2 million, or $0.07 per share, compared with net loss of $18.2 million, or $0.23 per share, in the prior quarter and net loss of $17.2 million, or $0.22 per share, in the year-earlier quarter. Adjusted net loss(1) for the third quarter was $5.6 million, and adjusted EPS(2) was a loss of $0.07 per share as compared to adjusted net loss of $14.8 million, and an adjusted EPS loss of $0.19 per share in the prior quarter, and adjusted net loss of $11.3 million, and an adjusted EPS loss of $0.15 per share in the year-earlier quarter.

Third quarter adjusted EBITDA(3) was $28.6 million, up from $16.9 million in the prior quarter and up from $14.0 million in the year-earlier quarter. The increase from the prior quarter was primarily due to a $9.7 million decrease in phantom stock compensation expense associated with the decrease in the fair value of the awards. Phantom stock compensation benefit during the third quarter was $3.7 million, while expense during the prior quarter was $6.1 million. The increase in adjusted EBITDA from the prior quarter was also due to improved margin per day in domestic drilling, and improved gross margin in both coiled tubing and well servicing. The increase from the year-earlier quarter was due to higher demand and pricing for all of our service offerings.

Operating Results

Production Services Business

Revenue from our production services business was $89.6 million in the third quarter, down 8% from the prior quarter and up 20% from the year-earlier quarter. Gross margin as a percentage of revenue from our production services business was 24% in the third quarter, up from 23% in the prior quarter and up from 22% in the year-earlier quarter. Despite the sequential decrease in revenue, which was attributable to softer wireline services activity and exacerbated by weather conditions in Texas, gross margin improved due to increased utilization in our coiled tubing segment and slightly improved utilization and pricing in our well servicing segment. During the third quarter, demand for our large-diameter coiled tubing services increased. Our well servicing segment also saw modest increases in completion-related services.

The decrease in production services revenues from the prior quarter was attributable to certain wireline customers that delayed completion activities in various regions in which we operate as well as a reduction in activity from weather-related events in the Gulf Coast region. This decline in wireline revenues was partially offset by increased demand for our coiled tubing and well servicing operations, both of which also experienced revenue growth sequentially. As compared to the year-earlier quarter, revenue rates have improved for all of our production services business segments, resulting in revenue growth of 20%.

Well servicing average revenue per hour was $552 in the third quarter, up from $540 in the prior quarter and up from $529 in the year-earlier quarter. Well servicing rig utilization was 51% in the third quarter, up from 49% in the prior quarter, and up from 43% in the year-earlier quarter. Coiled tubing revenue days totaled 362 in the third quarter, as compared to 350 in the prior quarter and 368 in the year-earlier quarter. The number of wireline jobs completed in the third quarter decreased 11% sequentially and decreased 3% as compared to the year-earlier quarter.

Drilling Services Business

Revenue from our drilling services business was $59.7 million in the third quarter, reflecting a 4% increase from the prior quarter and a 40% increase from the year-earlier quarter.

Our domestic drilling fleet was fully utilized during the current, prior and year-earlier quarters. Domestic drilling average revenues per day were $25,076 in the third quarter, up from $24,508 in the prior quarter and up from $23,873 in the year-earlier quarter. Domestic drilling average margin per day was $10,237 in the third quarter, up from $9,550 in the prior quarter and up from $9,084 in the year-earlier quarter. Revenue per day increased as compared to the prior and year-earlier quarters primarily due to certain contracts that re-priced at higher dayrates. Margin per day increased primarily from improvement in supplies, repair and maintenance costs that returned to normalized levels, as well as improvement in average dayrates from several rigs which repriced higher between $2,000 per day and $5,000 per day, offset by two rigs which re-priced lower by approximately $5,000 per day in August and September.

International drilling rig utilization was 76% for the third quarter, down from 85% in the prior quarter and up from 38% in the year-earlier quarter. International drilling average revenues per day were $41,158, up from $35,061 in the prior quarter and up from $26,155 in the year-earlier quarter, while average margin per day for the third quarter was $7,327, down from $7,583 in the prior quarter and up from $2,773 in the year-earlier quarter. Utilization and margin per day in the third quarter were down sequentially as one rig was released in early September as a client made adjustments to its drilling program, and another rig incurred non-revenue days as it changed operators in August. The increase in revenue per day was primarily due to the recognition of demobilization revenues during the third quarter. Utilization is based on daywork days and mobilization days between wells, but does not include initial mobilization days on new contracts or demobilization days when contracts end, which impacted our utilization for the third quarter.

Currently, all 16 of our domestic drilling rigs are earning revenues, 14 of which are under term contracts, and five of our eight rigs in Colombia are earning revenue under daywork contracts, and one is earning revenue during demobilization. We expect to execute a contract for the one rig in Colombia that was idle for most of September, and it is expected to begin mobilizing in mid-November and begin drilling in early- to mid-December. A second rig was released in late October and is currently demobilizing; however, we are finalizing a new contract, and the rig is also expected to begin mobilizing in mid-November with an anticipated start date in early- to mid-December. In our domestic drilling operations, we continue to expect our contracted new-build drilling rig to be deployed to West Texas and begin operations in the first quarter of 2019.

Comments from our President and CEO

"Our third quarter results were driven by steady improvement in our domestic drilling operations, which are benefiting from strong demand and upward trending dayrates," said Wm. Stacy Locke, President and Chief Executive Officer. "Our fleet of top performing drilling rigs is securing new contracts at higher rates and staying fully utilized. The last remaining legacy new-build contract will reprice downward approximately $5,000 in the fourth quarter, but will be offset by three rigs repricing at higher dayrates between $2,000 per day and $5,000 per day. Our new-build rig is expected to mobilize to the Permian in the first quarter of 2019 to begin a three year term contract with an existing client. Similar to our most recent new-builds, this rig can walk 150 feet, pass over wellheads 21 feet high, contains two 2,000 horsepower mud pumps, a 7,500 psi mud system, a 500-ton high torque topdrive and can rack approximately 25,000 feet of five inch drill pipe. We believe it will be one of the highest margin and top performing rigs in the U.S. The outlook for domestic drilling operations remains very bright.

"In Colombia, we had one rig idle for the month of September but we expect to execute a contract with a multi-national client to begin mobilizing the rig in mid-November and to commence drilling operations in early- to mid-December. This new opportunity reflects our efforts in expanding our client base in Colombia and our growing reputation as a provider of excellent service and safety. In late October, we experienced another round of dayrate adjustments where several rigs re-priced upward between $1,000 per day and $3,000 per day. We are seeing improvement in rig utilization and dayrates in Colombia across the industry, and we remain optimistic that our international drilling operations will experience stronger pricing and demand trends in 2019.

"In our production services business, our high-spec well servicing rig fleet activity is gradually improving with modest increases in 24-hour work which includes drill-out completion work. We will be slowly adding the ancillary equipment necessary to provide operators with a complete drill-out solutions package and, as we add, we expect margins will improve. We see drill-out opportunity in a number of geographic areas. Similarly, coiled tubing activity and margins are improving as we adjust our fleet mix to more large-diameter coiled tubing units. Our new 2-3/8" unit delivered in July performed well during the quarter and, in December, we expect to deploy an additional new 2-3/8" coiled tubing unit that we anticipate will immediately begin contributing. Once this unit is delivered, five of our nine actively marketed units will be large-diameter pipe serving two good markets.

"Although we anticipate the normal seasonal slowdown in the fourth quarter and some impact from operators' exhausted capital budgets, we expect overall activity to remain healthy and improve as we enter into 2019."

Fourth Quarter 2018 Guidance

In the fourth quarter of 2018, revenue from our production services business segments is estimated to be flat to down 4% as compared to the third quarter of 2018. Margin from our production services business is estimated to be 20% to 23% of revenue. Domestic drilling services rig utilization is expected to be 100% and generate average margins per day of approximately $9,700 to $10,200. International drilling services rig utilization is estimated to average 67% to 72%, which is impacted by initial mobilization and demobilization days, and generate average margins per day of approximately $8,000 to $9,000. We expect to have seven rigs operating on daywork rates in Colombia by the end of the fourth quarter.

We expect general and administrative expense to be $19 million to $20 million in the fourth quarter of 2018, which as it relates to phantom stock compensation expense, is based on the closing price of our common stock at September 30, 2018, which was $2.95.

Liquidity

Working capital at September 30, 2018 was $120.1 million, down from $130.6 million at December 31, 2017. Cash and cash equivalents, including restricted cash, were $53.5 million, down from $75.6 million at year-end 2017. During the nine months ended September 30, 2018, we used $48.8 million of cash for the purchase of property and equipment, and our cash provided by operations was $21.5 million.

Capital Expenditures

Cash capital expenditures during the nine months ended September 30, 2018 were $48.8 million, including capitalized interest. We estimate total cash capital expenditures for 2018 to be approximately $70 million, which includes $23 million for two large-diameter coiled tubing units, one of which was delivered in early July, three wireline units, two of which were delivered in January, high-pressure pump packages for completion operations, and the construction of the new-build drilling rig expected to be completed in 2019.

Conference Call

Pioneer Energy Services' management team will hold a conference call today at 11:00 a.m. Eastern Time (10:00 a.m. Central Time) to discuss these results. To participate, dial (412) 902-0003 approximately 10 minutes prior to the call and ask for the Pioneer Energy Services conference call. A telephone replay will be available after the call until November 6th. To access the replay, dial (201) 612-7415 and enter the pass code 13683786.

The conference call will also be webcast on the Internet and accessible from Pioneer Energy Services' web site at www.pioneeres.com. To listen to the live call, visit our web site at least 10 minutes early to register and download any necessary audio software. For more information, please contact Donna Washburn at Dennard Lascar Investor Relations at (713) 529-6600 or e-mail dwashburn@dennardlascar.com.

About Pioneer

Pioneer Energy Services provides well servicing, wireline, and coiled tubing services to producers in the U.S. Gulf Coast, Mid-Continent and Rocky Mountain regions through its three production services business segments. Pioneer also provides contract land drilling services to oil and gas operators in Texas, the Mid-Continent and Appalachian regions and internationally in Colombia through its two drilling services business segments.

Statements we make in this news release that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements made in good faith that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, levels and volatility of oil and gas prices, the continued demand for drilling services or production services in the geographic areas where we operate, decisions about exploration and development projects to be made by oil and gas exploration and production companies, the highly competitive nature of our business, technological advancements and trends in our industry and improvements in our competitors' equipment, the loss of one or more of our major clients or a decrease in their demand for our services, future compliance with covenants under debt agreements, including our senior secured term loan, our senior secured revolving asset-based credit facility, and our senior notes, operating hazards inherent in our operations, the supply of marketable drilling rigs, well servicing rigs, coiled tubing units and wireline units within the industry, the continued availability of new components for drilling rigs, well servicing rigs, coiled tubing units and wireline units, the continued availability of qualified personnel, the success or failure of our acquisition strategy, including our ability to finance acquisitions, manage growth and effectively integrate acquisitions, the political, economic, regulatory and other uncertainties encountered by our operations, and changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment. We have discussed many of these factors in more detail in our Annual Report on Form 10-K for the year ended December 31, 2017, including under the headings "Special Note Regarding Forward-Looking Statements" in the Introductory Note to Part I and "Risk Factors" in Item 1A. These factors are not necessarily all the important factors that could affect us. Other unpredictable or unknown factors could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. All forward-looking statements speak only as of the date on which they are made and we undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise. We advise our shareholders that they should (1) recognize that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.

This news release contains non-GAAP financial measures as defined by SEC Regulation G. A reconciliation of each such measure to its most directly comparable U.S. Generally Accepted Accounting Principles (GAAP) financial measure, together with an explanation of why management believes that these non-GAAP financial measures provide useful information to investors, is provided in the following tables.

_________________________________

(1)

Adjusted net loss represents net loss as reported adjusted to exclude impairments and the related tax benefit and valuation allowance adjustments on deferred tax assets. We believe that adjusted net loss is a useful measure to facilitate period-to-period comparisons of our core operating performance and to evaluate our long-term financial performance against that of our peers, although it is not a measure of financial performance under GAAP. Adjusted net loss may not be comparable to other similarly titled measures reported by other companies. A reconciliation of net loss as reported to adjusted net loss is included in the tables to this news release.

(2)

Adjusted (diluted) EPS represents adjusted net loss divided by the weighted-average number of shares outstanding during the period, including the effect of dilutive securities, if any. We believe that adjusted (diluted) EPS is a useful measure to facilitate period-to-period comparisons of our core operating performance and to evaluate our long-term financial performance against that of our peers, although it is not a measure of financial performance under GAAP. Adjusted (diluted) EPS may not be comparable to other similarly titled measures reported by other companies. A reconciliation of diluted EPS as reported to adjusted (diluted) EPS is included in the tables to this news release.

(3)

Adjusted EBITDA represents income (loss) before interest expense, income tax (expense) benefit, depreciation and amortization, impairment, and any loss on extinguishment of debt. Adjusted EBITDA is a non-GAAP measure that our management uses to facilitate period-to-period comparisons of our core operating performance and to evaluate our long-term financial performance against that of our peers. We believe that this measure is useful to investors and analysts in allowing for greater transparency of our core operating performance and makes it easier to compare our results with those of other companies within our industry. Adjusted EBITDA should not be considered (a) in isolation of, or as a substitute for, net income (loss), (b) as an indication of cash flows from operating activities or (c) as a measure of liquidity. In addition, Adjusted EBITDA does not represent funds available for discretionary use. Adjusted EBITDA may not be comparable to other similarly titled measures reported by other companies. A reconciliation of net loss as reported to adjusted EBITDA is included in the tables to this news release.

(1) Adjusted EBITDA represents income (loss) before interest expense, income tax (expense) benefit, depreciation and amortization, impairment, and any loss on extinguishment of debt. Adjusted EBITDA is a non-GAAP measure that our management uses to facilitate period-to-period comparisons of our core operating performance and to evaluate our long-term financial performance against that of our peers. We believe that this measure is useful to investors and analysts in allowing for greater transparency of our core operating performance and makes it easier to compare our results with those of other companies within our industry. Adjusted EBITDA should not be considered (a) in isolation of, or as a substitute for, net income (loss), (b) as an indication of cash flows from operating activities or (c) as a measure of liquidity. In addition, Adjusted EBITDA does not represent funds available for discretionary use. Adjusted EBITDA may not be comparable to other similarly titled measures reported by other companies. A reconciliation of net loss as reported to adjusted EBITDA is included in the table on page 14.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

Operating Statistics

(unaudited)

Three months ended

Nine months ended

September 30,

June 30,

September 30,

2018

2017

2018

2018

2017

Domestic drilling:

Average number of drilling rigs

16

16

16

16

16

Utilization rate

99

%

100

%

100

%

100

%

93

%

Revenue days

1,459

1,472

1,454

4,353

4,052

Average revenues per day

$

25,076

$

23,873

$

24,508

$

24,844

$

23,188

Average operating costs per day

14,839

14,789

14,958

14,771

15,217

Average margin per day

$

10,237

$

9,084

$

9,550

$

10,073

$

7,971

International drilling:

Average number of drilling rigs

8

8

8

8

8

Utilization rate

76

%

38

%

85

%

79

%

40

%

Revenue days

562

283

621

1,733

865

Average revenues per day

$

41,158

$

26,155

$

35,061

$

36,073

$

30,496

Average operating costs per day

33,831

23,382

27,478

28,297

23,333

Average margin per day

$

7,327

$

2,773

$

7,583

$

7,776

$

7,163

Drilling services business:

Average number of drilling rigs

24

24

24

24

24

Utilization rate

92

%

79

%

95

%

93

%

75

%

Revenue days

2,021

1,755

2,075

6,086

4,917

Average revenues per day

$

29,548

$

24,241

$

27,666

$

28,042

$

24,474

Average operating costs per day

20,120

16,174

18,705

18,622

16,644

Average margin per day

$

9,428

$

8,067

$

8,961

$

9,420

$

7,830

Well servicing:

Average number of rigs

125

125

125

125

125

Utilization rate

51

%

43

%

49

%

49

%

44

%

Rig hours

44,155

36,108

42,871

127,800

114,697

Average revenue per hour

$

552

$

529

$

540

$

537

$

513

Wireline services:

Average number of units

104

117

108

107

115

Number of jobs

2,684

2,778

3,022

8,536

8,540

Average revenue per job

$

19,618

$

16,589

$

20,562

$

20,079

$

13,872

Coiled tubing services:

Average number of units

11

14

14

13

16

Revenue days

362

368

350

1,126

1,106

Average revenue per day

$

34,785

$

25,951

$

34,503

$

33,654

$

20,355

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

Reconciliation of Net Loss to Adjusted EBITDA

and Consolidated Gross Margin

(in thousands)

(unaudited)

Three months ended

Nine months ended

September 30,

June 30,

September 30,

2018

2017

2018

2018

2017

Net loss as reported

$

(5,233)

$

(17,227)

$

(18,152)

$

(34,524)

$

(62,560)

Depreciation and amortization

23,501

24,623

23,287

70,535

74,355

Impairment

239

—

2,368

2,607

795

Interest expense

9,811

6,613

9,642

28,966

19,090

Income tax expense (benefit)

258

17

(249)

1,297

1,200

Adjusted EBITDA(1)

28,576

14,026

16,896

68,881

32,880

General and administrative

14,043

17,549

24,829

58,066

51,405

Bad debt recovery, net of expense

111

491

(370)

(311)

(98)

Gain on dispositions of property and equipment, net

(1,861)

(1,159)

(726)

(2,922)

(2,251)

Other income

(498)

(295)

(44)

(1,046)

(224)

Consolidated gross margin

$

40,371

$

30,612

$

40,585

$

122,668

$

81,712

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

Reconciliation of Net Income (Loss) as Reported to Adjusted Net Income (Loss)

and Diluted EPS as Reported to Adjusted (Diluted) EPS

(in thousands, except per share data)

(unaudited)

Three months ended

September 30,

June 30,

2018

2017

2018

Net loss as reported

$

(5,233)

$

(17,227)

$

(18,152)

Impairment

239

—

2,368

Tax benefit related to adjustments

(56)

—

(556)

Valuation allowance adjustments on deferred tax assets

(581)

5,894

1,501

Adjusted net loss(2)

$

(5,631)

$

(11,333)

$

(14,839)

Basic weighted average number of shares outstanding, as reported

78,136

77,552

77,944

Effect of dilutive securities

—

—

—

Diluted weighted average number of shares outstanding, as adjusted

78,136

77,552

77,944

Adjusted (diluted) EPS(3)

$

(0.07)

$

(0.15)

$

(0.19)

Diluted EPS as reported

$

(0.07)

$

(0.22)

$

(0.23)

(2) Adjusted net loss represents net loss as reported adjusted to exclude impairments and the related tax benefit and valuation allowance adjustments on deferred tax assets. We believe that adjusted net loss is a useful measure to facilitate period-to-period comparisons of our core operating performance and to evaluate our long-term financial performance against that of our peers, although it is not a measure of financial performance under GAAP. Adjusted net loss may not be comparable to other similarly titled measures reported by other companies. A reconciliation of net loss as reported to adjusted net loss is included in the table above.

(3) Adjusted (diluted) EPS represents adjusted net loss divided by the weighted-average number of shares outstanding during the period, including the effect of dilutive securities, if any. We believe that adjusted (diluted) EPS is a useful measure to facilitate period-to-period comparisons of our core operating performance and to evaluate our long-term financial performance against that of our peers, although it is not a measure of financial performance under GAAP. Adjusted (diluted) EPS may not be comparable to other similarly titled measures reported by other companies. A reconciliation of diluted EPS as reported to adjusted (diluted) EPS is included in the table above.